This invention relates to a separator for separating multiphase flow and, in particular, a separator which can be utilised as part of the subsea assembly described in our co-pending European patent application entitled “Subsea Process Assembly” and filed on the same day (agent's ref: MJBO7O59EP), both hereby incorporated herein by reference.
In general, the current practice for development of subsea hydrocarbon fields is on a macro field approach which uses a plurality of subsea wells connected through a subsea infrastructure, pipelines and risers to a surface process facility, such as a floating production vessel or a platform. In many locations, especially in remote areas, the proportion of gas and water within the fluid produced by the well is significant and is generally a surplus product, when compared to the oil which it is usually desired to retrieve. The gas and water has to be safely and cleanly disposed of in a manner which does not damage the environment.
A solution for such a system is that gas and water which have been taken out of the well and which are separated at the surface can be pumped back to the seabed to be reinjected at the seabed into subsea wells. This re-injection reduces the rate of decline of the reservoir pressure allowing the field to produce for longer. To increase the rate of production, energy must be supplied to the production stream using either downhole or seabed methods.
Overall, the current approach requires a complex field production system which has numerous pipelines, thus incurring a high field capital expenditure and operational expenditure. This high expenditure reduces the commercial ceiling at which the field can be operated viably. As the field matures and production declines, a level is reached at which considerable resources are left in place but at which it is no longer commercially viable to operate the wells.
Conventionally, the flow which is achieved from a subsea well is directed to a surface production vessel. Back pressure on the well reduces the production rate and brings on an early decline of the wells flowing life as the reservoir pressure at the bottom of the well must overcome the hydrostatic head and the pressure caused by friction. Therefore the well depth, the distance along the seabed and the water depth are all contributing factors against the reservoir pressure. At a certain stage, the well ceases to produce a useable flow when a significant proportion of the desired fluid remains in the reservoir area drained by the well. Energy can be added to the production stream, either downhole, at the wellhead or in the riser. The input of energy increases the lift cost of the oil from the well, thereby reducing the commercial viability of the well and, in some cases, the entire field.
In deep water or for wells at a considerable distance, such as over a number of kilometres from the surface production vessel, the production rate decline or the energy input causes the commercial value of a field to be reduced quicker. The early non-viability of the field means considerable valuable resources such as the non recovered natural resources are left in situ. Accordingly, and especially in deep water, the limited production rates, the early decline and the higher costs result in an increased investment requirement with a lower rate of return. This ensures that small and medium sized fields cannot be exploited fully, if at all, using current practices.
When wells are at a considerable horizontal distance along the seabed from the surface production vessel, a number of significant problems such as slugging, hydrates, waxing and an increased back pressure are caused by the distance that the production fluid must travel. In addition, using gas artificial lift in the well can exacerbate these problems causing pipelines to require higher specifications and larger diameters, thereby increasing the cost.
In order to maximise the production capability of a well, well operators are considering solutions which are based on the macro field approach and these include downhole gas lift or pumping, seabed drive, multiphase pumping, gas/liquid separation, hydrocarbon/water separation, individual well gas/liquid separation and three phase separation.
As the pressure in the reservoir declines and at different rates in different parts of the field, the volume produced from the wells will also decline. To maintain an effective production rate requires the addition of artificial lift in the wells that increases the seabed wellhead flowing pressure. This means that, in pumped wells, a considerable amount of gas will still be in solution at the wellhead.
In a macro field approach, the wells produce flowing up to the subsea trees along to a manifold where the flow from individual wells is commingled and then the multiphase fluid flows to the surface via pipelines and risers. To reduce the back pressure caused by the pipelines, methods for providing energy to the flow stream downstream of the manifold, such as additional pumps, may be used. As the fluid flows up the well the gas will come out of solution once it is above the bubble point, thereby causing a gas/liquid flow at the wellhead. However, such multiphase pumps require additional energy which increases the cost of this approach. The requirements for pumping this free gas are very different and, in many cases, opposite to those required for pumping liquid and therefore there is a design conflict and, at best, only a poor compromise can be achieved. Therefore it is preferable to separate the fluid into gas and liquid which can be directed to suitable gas pumps and liquid pumps. As friction losses along a pipeline reduce the pressure, more and more gas comes out of the liquid solution, possibly forming 50 to 100 metre slugs of gas. It should be considered that this gas does not need pumping due to the low gas friction factor and low gas hydrostatic head, and can freely travel along its own pipeline. It is the liquid slugs that have to be pushed along by the compressed gas. Accordingly, the energy used by a multiphase pump to compress the gas to achieve a pressurised multi phase flow is unnecessary if a separate gas flow line is used.
On the surface, large pressure resistant sealed tanks can be used to provide adequate standing time for the flow to separate into the gas, oil, water and solids slurry phases. To separate fluids at high pressures on the surface, or subsea, or at low pressures in deeper waters requires separators that can withstand burst, collapse or both. Large conventional tanks are no longer suitable and smaller tanks capable of withstanding high internal and/or external pressures have to be used.
The reduced size either reduces the volume throughput or several have to be used considerably increasing the complexity. This outline has covered the conventional approach to subsea separation of wellhead fluids.
Subsea gas/liquid separation and pumping can partially take advantage of the wellhead at the seabed and the water depth. The gas can be separated at a lower pressure than the lowest pressure point in the pumped liquid pipeline. Such a system is described in U.S. Pat. No. 4,900,433 by disclosing a drilling approach using a conventional subsea conductor as a separator housing. Due to the conductor size, a maximum throughput of about 30,000 barrels per day is what can be expected from such a system. The concept disclosed in U.S. Pat. No. 4,900,433 is based on a combination of two principles. A general description of how these principles behave in respect to separation is that, firstly, the fluid is allowed to flow into a large downwardly angled flow trough which allows the fluid velocity to be reduced down to a maximum of 2 to 3 metres per second. The velocity of the fluid down the trough is controlled by the downward angle. In a long straight trough, the length is dependent on the time required to allow the gas to percolate up in respect of the depth of the trough or for oil/water to form a two layered flow. The depth of, and velocity of the fluid in, the trough determines the length of the trough required. Secondly, the trough is now wound around a central core in a helix manner, with the assembly installed into a subsea conductor or it could be part of a seabed silo mounted on the seabed. The fluid in the trough is now subjected to a rotational force which exerts a centrifugal gravitational force on the bubbles or forming droplets.
The trough length can now be shortened as it is inversely proportional to the rotational gravitational effect. As the trough is wound around the central core, a number of rotations can be achieved per metre of hole. The resulting circumference of the circular helix trough means a considerable helix travel distance can be achieved in either the depth of hole or in the silo height.
Although the separation is efficient, the volume throughput is limited by the constraining diameter and the length of the conductor. The height required for a silo could lead to a high profile on the seabed and possible snagging problems.
The principles of separation of fluid are now described. The separation of fluids (gas, oil and water) is a physical operation and occurs naturally if the fluid is left in a uniform state. The rate of separation at a set pressure is given by Stoke's Law which states:
      S    =                  cgd        2            ⁡              (                              p            2                    -                      p            1                          )              μ
Where:                S—terminal velocity or rate of separation        C—constant        g—gravity        d—diameter of droplet        p2—density of surrounding fluid        p1—density of droplet        μ viscosity of surrounding fluid        
This shows that the diameter of a droplet, bubble or particle, being squared, is an important factor that defines the rate of separation.
This applies to the free gas bubbles, or droplets of either oil or water in the surrounding fluid. At a certain pressure, a quantity of gas will be in solution which cannot be separated out at this pressure. If the pressure is lowered, more gas will come out of solution. Therefore it is important to operate the separator at a pressure level that will achieve the correct level of gas/liquid separation as defined for the system. The pressure level will not affect the size of solids and only marginally affect the size of liquid droplets.
The two variable but critical factors in the separation process between two fluids of defined density, viscosity and pressure are the diameter of the bubble or droplet and the effect of gravity.
In a large stationary fluid separation tank, taking the effect of gravity on the earth surface as 1 g, only 1 g is applied resulting ma 10-15 minute standing time to achieve a level of separation between different liquids. By rotating the fluid, the g forces can be increased, (e.g. by using a centrifuge the force are increased to 5000 g and using a hydrocyclone to 2000 g).
The centrifugal force created by a rotating item whether a unit mass, droplet, bubble or particle is given by:
      C    f    =            m      ⁢                          ⁢              V        2              r  
Where:                Cf—centrifugal force        m—mass of item        V—velocity        r—radius of rotation        
This shows that the velocity being squared is a sensitive value to increasing the separation factor for a set radius of rotation. The combination of the radius of curvature and the velocity will define the flow rate through the separator. The volume of the separator is dependent on the time to achieve the desired level of separation of the flow rate.
A separator in which the g forces are high is therefore very efficient, providing the particle or materials being separated remain the same size. (i.e. sand and debris in a liquid).
The main disadvantage of these high g force separators for separating moving liquids in a fixed cyclone or helix compared with a stationary fluid in a centrifuge is the high shear stress forces which results in breaking down the droplet size, causing smaller droplets, even creating emulsions. To either reduce the effect of emulsions or to rectify the problem, chemical additives can be used. Therefore the advantage of a higher gravity force is overshadowed by the drastically reduced droplet diameter because the separation force is dependent on the square of the droplet diameter.
A gradual reduction of droplet diameter in a moving fluid occurs down to 20 g, but above this value a large reduction in droplet diameter occurs with the effect that higher gravity forces now only causes a minor increase in the rate of separation.
It is therefore critical to keep the droplet diameters as large as possible by creating a gravity effect between 10-20 g and by keeping the velocity of the fluid between a maximum of 2-3 m/s.